Model-based load demand control

ABSTRACT

Embodiments of methods and systems for controlling a load generated by a power generating system may include controlling at least a portion of the system using model-based control techniques. The model-based control techniques may include a dynamic matrix controller (DMC) that receives a load demand and a process variable as inputs and generates a control signal based on the inputs and a stored model. The model may be configured based on parametric testing, and may be modifiable. Other inputs may also be used to determine the control signal. In an embodiment, a turbine is controlled by a first DMC and a boiler is controlled by a second DMC, and the control signals generated by the first and the second DMCs are used in conjunction to control the generated load. Techniques to move the power generating system from Proportional-Integral-Derivative based control to model-based control are also disclosed.

TECHNICAL FIELD

This patent relates generally to the control of process and powergenerating equipment and, in particular, to the implementation ofmodel-based load demand control to be used in reducing the controlresponse time of power generating equipment/process or other plantequipment with similar response characteristics.

BACKGROUND

A variety of industrial as well as non-industrial applications use fuelburning boilers which typically operate to convert chemical energy intothermal energy by burning one of various types of fuels, such as coal,gas, oil, waste material, etc. An exemplary use of fuel burning boilersmay be in thermal power generators, wherein fuel burning furnacesgenerate steam from water traveling through a number of pipes and tubeswithin a boiler, and the generated steam may be then used to operate oneor more steam turbines to generate electricity. The electrical or poweroutput of a thermal power generator may be a function of the amount ofheat generated in a boiler, wherein the amount of heat may be directlydetermined by the amount of fuel consumed (e.g., burned) per hour, forexample.

A typical steam generating system used in a power plant may include aboiler having a superheater section (having one or more sub-sections) inwhich steam may be produced and may be then provided to and used withina first, typically high pressure, steam turbine. To increase theefficiency of the system, the steam exiting this first steam turbine maythen be reheated in a reheater section of the boiler, which may includeone or more subsections, and the reheated steam may be then provided toa second, typically lower pressure steam turbine. However, as may beknown, both the furnace/boiler section of the power system as well asthe turbine section of the power system must be controlled in acoordinated manner to produce a desired amount of power.

Moreover, as may be known, the steam turbines of a power plant aretypically run at different operating levels at different times toproduce different amounts of electricity or power based on variableenergy or load demands provided to the power plant. For example, in manycases, a power plant may be tied into an electrical power distributionnetwork, sometimes called a power grid, and provides a designated amountof power to the power grid. In this case, a power grid manager orcontrol authority typically manages the power grid to keep the voltagelevels on the power grid at constant or near-constant levels (that maybe, within rated levels) and to provide a consistent supply of powerbased on the current demand for electricity (power) placed on the powergrid by power consumers. Of course, the grid manager typically plans forheavier use and thus greater power requirements during certain times ofthe days than others, and during certain days of the week and year thanothers, and may run one or more optimization routines to determine theoptimal amount and type of power that needs to be generated at anyparticular time by the various power plants connected to the grid tomeet the current or expected overall power demands on the power grid.

As part of this process, the grid manager typically sends power or loaddemand requirements (also called load demand set points) to each of thepower plants supplying power to the power grid, wherein the power demandrequirements or load demand set points specify the amount of power thateach particular power plant may be to provide onto the power grid at anyparticular time. Of course, to effect proper control of the power grid,the grid manager may send new load demand set points for the differentpower plants connected to the power grid at any time, to account forexpected and/or unexpected changes in power being supplied to orconsumed from the power grid. For example, the grid manager may changethe load demand set point for a particular power plant in response toexpected or unexpected changes in the demand (which may be typicallyhigher during normal business hours and on weekdays, than at night andon weekends). Likewise, the grid manager may change the load demand setpoint for a particular power plant in response to an unexpected orexpected reduction in the supply of power on the grid, such as thatcaused by one or more power units at a particular power plant failingunexpectedly or being brought off-line for normal or scheduledmaintenance.

In any event, while the grid manager may provide or change the loaddemand set points for particular power plants at any time, the powerplants themselves cannot generally increase or decrease the amount ofpower being supplied to the power grid instantaneously, because powergeneration equipment typically exhibits a significant lag in responsetime due to the physical characteristics of these systems. For example,to increase the power output of a steam turbine based power generationsystem, it may be necessary to change the amount of fuel being spentwithin the system, to thereby increase the steam pressure or temperatureof the water within the boiler of the system, all of which takes afinite and non-trivial amount of time. Thus, generally speaking, powerplants can only ramp up or ramp down the amount of power being suppliedto the grid at a particular rate, which may be based on the specifics ofthe power generating equipment within the plant. Thus, when the gridmanager changes the load demand set point for any particular powerplant, the grid manager typically provides both a new target load demand(to be reached at some particular time in the future) and a ramp ratespecifying the manner in which the load demand set point changes overthe time between the current time and the particular time in the future.Generally speaking, the ramp rate indicates the manner in which the loaddemand set point for the power plant may be to ramp up or down (change)over time between the current load demand set point and the target loaddemand set point.

In power plants that use a boiler to produce power, a power plantcontroller typically uses a feedforward controller to increase ordecrease the output power in response to a change in the load demand,which may be made either locally or by a remote dispatch (e.g., by thegrid manager). To change output power of the plant, the load demand setpoint (which may be expressed as a power demand, e.g., megawatts, or asa percentage of capacity) may be typically converted to a unit loadindex which serves as a master feedforward demand signal for both theboiler and the turbine of each power generator unit. The boiler masterdemand signal then becomes the basis for producing both a master fuelcontrol signal and a master air control signal used to control the fuel(e.g., coal) and the air flow provided to the furnace of the boiler.

Due to the sluggish nature of a boiler response however, the boilermaster (or fuel master) demand may be typically computed with aderivative component (i.e., a “lead” component from a frequency domaintransfer function perspective), or a so-called “kicker,” which increasesthe response rate of the boiler, instead of using a simple linearfunction of the load demand index (a straight line) as the feedforwardcontrol signal. An immediate drawback of using a derivative action as abasis for adding a lead component or a “kicker” when computing thefeedforward control signal may be that this derivative component riskscreating a large overshoot and swing in both the unit load and the steamtemperature of the boiler when the change in the load demand set pointmay be large and/or the load demand set point ramps or ranges over along period of time. This problem may be especially prominent forrelatively fast response boilers (for example, cyclone boilers).

To solve the problem of overshoot and swing, it may be known to derivethe unit load index based feedforward control signal to include aderivative “kicking” action based on the difference between the currentload demand set point and the final target load demand set point, suchthat the derivative kicking action may be stronger or more prominent atthe beginning of the load demand ramp (when the difference between thecurrent load demand set point and the target load demand set point maybe above a preset threshold) and the derivative action weakenssignificantly (or may be halted altogether) near the end of the ramp(i.e., when the difference between the current load demand set point andthe target load demand set point may be less than a preset threshold).However, this strategy has significant shortcomings in that (1) thistechnique loses the derivative “kicking” action when the load demandramp range may be relatively small (i.e., when the difference between acurrent load demand set point and the final target load demand set pointmay be initially small to begin with) and (2) this technique has to relyon the knowledge of the final target load demand set point to determinewhen to remove or lessen the derivative “kicking” action within thefeedforward control signal.

Unfortunately, many changes made to the load demand set point by, forexample, a grid manager, are relatively small in nature and, in manycases, may not be large enough to initiate any derivative “kicking”action when a change in load demand may be initially made by the gridmanager (which may be the time that the derivative “kicking” action maybe most beneficial). Additionally, in many instances, the actual finalor target load demand set point value may be unknown to the controlsystem of the process plant producing the power because the remotedispatch center or grid manager only sends an incremental pulse signalto the local plant increasing the load demand set point, withoutinforming the plant of the final target load demand to which the plantmay be moving. In this case, the addition of the derivative “kicking”action may be difficult or impossible to apply with any certainty oreffectiveness as the plant must estimate a target or final load demandset point (which may lead to over-aggressive control) or must assumethat the target load demand set point may be simply the next value sentby the dispatcher (which typically leads to under-aggressive control).

SUMMARY

Embodiments of a method of controlling a load generated by a powergenerating system may include receiving a signal indicative of a loaddemand at an input of a dynamic matrix controller. The method mayadditionally include determining a value of a control signal based onthe signal indicative of the load demand and a model stored in a memoryof the dynamic matrix controller, and generating the control signal. Themethod may also include controlling the load generated by the powergenerating system based on the control signal. In an embodiment, thecontrol signal may be determined further based on a current value of aprocess variable and a desired value of the process variable. In anembodiment, more than one model-based controlled entity may eachgenerate a respective control signal, and the resulting one or moregenerated control signals may be combined to control the load generatedby the power generating system.

Embodiments of a method of controlling a load of a power generatingsystem may include generating, by a first dynamic matrix controller, afirst control signal based on a load demand and a first model stored ina memory of the first dynamic matrix controller, and generating, by asecond dynamic matrix controller, a second control signal based on theload demand and a second model stored in a memory of the second dynamicmatrix controller. The method may further include controlling the loadof the power generating system based on the first control signal and onthe second control signal. The first dynamic matrix controller maycorrespond to a turbine and the second dynamic matrix controller maycorrespond to a boiler, in an embodiment. In some embodiments, themethod may include initiating a cessation of aProportional-Integral-Derivative (PID) control technique prior to thedynamic matrix controller generating a control signal.

Embodiments of a power generating system may include a dynamic matrixcontroller. The dynamic matrix controller may include an input toreceive a signal indicative of a load demand for the power generatingsystem, a memory storing a model, a dynamic matrix control routineconfigured to determine a value of a control signal based on the modeland a value of the load demand, and an output to provide the controlsignal to control a load generated by the power generating system. Themodel may be determined or configured based on parametric testing of atleast a portion of the power generating system, and the model may bemodifiable. In some embodiments, the dynamic matrix controller mayinclude one or more additional inputs, and the dynamic matrix controlroutine may determine the value of the control signal further based onthe one or more additional inputs.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 illustrates a block diagram of a power grid having numerous powergenerating plants connected thereto, at least one of which includesmodel-based load demand control;

FIG. 2 illustrates a block diagram of a dynamic matrix controller (DMC)used to provide model-based load control in a power generating plant orsystem;

FIG. 3 illustrates an example screen shot of a user interface of a powergenerating plant or system displaying a model that may be included inthe dynamic matrix controller of FIG. 2;

FIG. 4 illustrates a block diagram of a power grid having numerous powergenerating plants connected thereto, at least one of which may beswitched between model-based load demand control andProportional-Integral-Derivative (PID) control;

FIG. 5 illustrates an example block diagram of an arrangement that maybe used as part of Proportional-Integral-Derivative (PID) control tocontrol a power generating unit;

FIG. 6 illustrates an example method of controlling a load of a powergenerating system;

FIG. 7 illustrates an example method of controlling a load generated bya power generating system; and

FIG. 8 illustrates an embodiment of a method for generating a model foruse in model-based control of a power generating system.

DETAILED DESCRIPTION

Referring now to FIG. 1, a power grid 10 may be electrically andcommunicatively connected to each of a number of power plants 12, 14 and16, as well as to additional power plants not shown in FIG. 1, whereinthe power plants 12, 14, 16 may operate to provide power to the powergrid 10. As used herein, the terms “power plant,” “power generatingplant,” “power generating system,” “load generating plant,” and “loadgenerating system” are used interchangeably.

As will be understood, the power on the power grid 10 may be used or maybe consumed by customers or other power consumers (not shown in FIG. 1)connected to the power grid 10. Generally speaking, a grid manager,indicated in FIG. 1 as a system operator (SO) 20, may be connected toand may manage the power on the grid 10 by determining and then sendingdifferent load demand set point signals to each of the plants 12, 14 and16. These load demand set point signals may be generated by the systemoperator 20 in any known or desired manner and may, for example, begenerated using an optimization technique. Generally speaking, theseload demand set point signals may indicate the amount of power(generally in terms of megawatts) to be provided by each plant 12, 14and 16 to the power grid 10 at any particular time. More particularly,the system operator 20 may maintain the voltage level on the power grid10 at a rated level and may assure that enough power (both active andreactive) may be provided to the power grid 10 to satisfy the currentand/or the projected future demand on the power grid 10 at anyparticular time by generating and sending load demand set point signalsto each of the plants 12, 14 and 16.

Unfortunately, as is generally known, the power plants 12, 14, 16 cannotinstantaneously change the amount of power being provided to the powergrid 10, especially if the power plants 12, 14, 16 use slow-reactingtypes of power generating equipment, such as pulverized coal-fired powergenerating units. Thus, the system operator 20, when providing eachpower plant 12, 14, 16 with a load demand set point signal, generallydoes so by providing a new target load demand set point to be reached atsome point in the future and a rate at which the power plant may be toramp up to the target load demand set point (thereby specifying a set ofload demand set point signals to be used between the current time andthe time at which the target load demand set point signal may be to bereached). Thus, the system operator 20 may provide a power plant, forexample, the power plant 14, with a new target load demand set point tobe reached at a particular time in the future and a ramp rate at whichthe power output by the power plant 14 will change over the time betweenthe current time and the time at which the target load demand set pointmay be to be reached. Generally speaking, the ramp rate provided by thesystem operator 20 to any particular power plant 12, 14, 16 may be basedon (i.e., may be equal to or less than) the maximum allowed or specifiedrate at which these plants may change their power output, which may beprovided by the plants 12, 14, 16 to the system operator 20 when theplants 12, 14, 16 come on-line or are commissioned or signed up forregulation control. In other circumstances, however, the system operator20 may provide each power plant 12, 14, 16 with a new load demand setpoint at numerous periodic times (such as once every minute, once every10 minutes, etc.) with the new load demand at each time being calculatedto be within the specified or allowable ramp rate for each power plant.

In any event, referring again to FIG. 1, the system operator 20 mayprovide, periodically or at non-fixed times, new load demand set pointsignals to each of the plants 10, 12, 14, and these load demand setpoint signals may include load demand set points which may be providedto a load demand computer (LDC) 22 located within each of the plants 12,14, 16. The LDCs 22 within the plants 12, 14 and 16 may use the loaddemand set points as primary control signals to be used to control theindividual power generating units within the plant. As illustrated forthe plant 14, which may be, in this be case, a boiler operated steamturbine power plant, an LCD 22 uses the received load demand set pointsignal to produce a load demand index, which may be then provided to aturbine master control unit 24 and to a boiler master control unit 26within the plant 14. As shown in FIG. 1, the turbine master control unit24 may use the LDC index and model-based control to control turbinevalves 28 and bypass valves 30, as well as additional or other turbineequipment used to generate electricity based on steam produced by theboiler system of the plant. In a similar manner, the boiler mastercontrol unit 26 may use the LDC index provided by the LDC 22 andmodel-based control to compute a fuel flow, air flow, and/or water flowdemand signal 32 used within the boiler system to control the operationsof fans 34, mills 36, pumps 38, valves 40, as well as other equipmentwithin the boiler system to operate the boiler to produce the amount ofsteam pressure needed to drive the turbines at a particular powergenerating capacity.

Model-based control techniques used in a power generating system tocontrol a generated load (such as those used in conjunction with theturbine master 24 and the boiler master 26) may provide significantadvantages over traditionally utilized control techniques such asProportional-Integral-Derivative (PID) control. Boilers and othercomponents of power generating systems have inherently sluggish responsetimes. As PID control techniques generally are reactionary, the slowcomponent response is exacerbated. Accordingly, only after theoccurrence of a discrepancy between a setpoint and a process variable(e.g., throttle pressure, unit load, megawatts, etc.) does correctionalaction begin to take place. Even with additional enhancements to PIDcontrol such as feed forward and “kicker” components, the response timeto ramp up to a desired load demand may still not be sufficientlyprecise or efficient, thus adding to operational costs and cutting intothe profits of the power generating system.

On the other hand, model-based control of various power generating plantsections (e.g., the turbine and/or the boiler) may provide increasedefficiency and precision as well as decreased ramp-up time to generate adesired load. In an embodiment, the model-based control of the turbinemaster control unit 24 and/or of the boiler master control unit 26 mayeach include a respective dynamic matrix controller having one or morerespective models stored thereon that are used to generate controlsignals. Given a desired load demand, the dynamic matrix controller(s)may control the turbine master 24 and/or the boiler master 26 directlyto a desired configuration based on the one or more respective models,rather than controlling the turbine master 24 and/or the boiler master26 by performing time-consuming linear calculations of discrepancies andreactionary hunting for manipulated variables, as required by PIDcontrol techniques. As such, correctional action may be instantaneousrather than reactionary. Further, the step-like response of themodel-based control techniques disclosed herein may allow the loadgenerating system to raise and lower the generated load with lessovershoot and less undershoot. Still further, the one or more modelsused in model-based control techniques may be ready for immediate useafter they are loaded, whereas PID control techniques requireconsiderable tuning before they are ready for use. For at least thesereasons, generated loads may be more efficiently and more timelydispatched, thus resulting in significant cost savings.

FIG. 2 illustrates an embodiment of a general block diagram of a dynamicmatrix controller (DMC) 100 that may be used to provide model-based loadcontrol in a power generating system or plant, such as the plant 12, 14or 16 of FIG. 1. For example, a particular instance of the DMC 100 shownin FIG. 2 may be included in or may operate in conjunction with theturbine master control unit 24, and a same or different instance of theDMC 100 may be included in or may operate in conjunction with the boilermaster control unit 26. In an embodiment, the turbine master 24 includesa first instance of the dynamic matrix controller 100, and the boilermaster 26 includes a different instance of the dynamic matrix controller100.

The dynamic matrix controller 100 may include one or more inputs 102a-102 f to receive various signals from the power generating system. Inan embodiment, the DMC 100 includes an input 102 a at which a signalindicative of a load demand may be received. For example, the input 102a may receive a signal corresponding to an LDC index from the LDC 22.

The DMC 100 may receive, in some embodiments, one or more additionalinputs 102 b-102 f. In an embodiment, the DMC 100 may include an input102 b via which a signal indicative of a current value of a processvariable used in the load generating system may be received, and mayinclude an input 102 c via which a signal indicative of a desired valueof the process variable (e.g., the setpoint of the process variable) maybe received. For example, the input 102 b may receive a signalcorresponding to a current value of a throttle pressure; a fuel flow,air flow to the system and/or water flow to the system; a unit load; anamount of generated power (e.g., in megawatts or some other suitableunit of measure); or another suitable process variable.

In an embodiment, the DMC 100 includes an input 102 d at which a signalindicative of a current value of a manipulated variable used in the loadgenerating system may be received. For example, the input 102 d mayreceive a signal corresponding to a current value that represents avalve position, a damper position or some other manipulated variablethat may affect control of a load generated by the power generatingsystem. In an embodiment, the manipulated variable whose value isreceived at the input 102 d may correspond to one or more of the valves28, 30 or 40, the fan 34, the mill 36, the pump 38, or some other entityof the load generating system. In an embodiment, more than one signalcorresponding to more than one manipulated variable may be received atthe DMC 100.

In some embodiments, an input 102 e of the DMC 100 may receive a signalindicative of a disturbance variable. A disturbance variable maycorrespond to, for example, an amount of soot, a steam temperature, anamount of burner tilt, or any other disturbance that may affect controlof a load generated by the power generating system. In an embodiment,one or more other inputs 102 f of the DMC 100 may receive one or moreother signals.

At the DMC 100, based on the values of one or more signals received atthe inputs 102 a-102 f, a dynamic matrix control routine 105 maydetermine a value of a control signal 108. In particular, the dynamicmatrix control routine 105 may determine the value of the control signal108 based on a model 110 that may be represented by the function

D(i _(i) ,i ₂ , . . . i _(n))=c,

where i_(x) corresponds to a value of a signal received at an x-th inputof the DMC 100, and c corresponds to a value of the control signal 108generated by the DMC 100. In an example, when an instance of the DMCmodel 100 is included in the turbine master 24 of FIG. 1, the controlsignal 108 may be provided to control one or more turbine valves 28, oneor more bypass valves 30, and/or other entities in the power generatingplant that affect control of the turbine. In another example, when adifferent instance of the DMC model 100 is included in the boiler master26 of FIG. 1, the control signal 108 may be provided to control a fuelflow, an air flow and/or a water flow 32, one or more fans 34, mills 36,pumps 38, valves 30, or other entities within the power generating plantthat affect control of the boiler.

At a minimum, the dynamic matrix control routine 105 may determine thecontrol signal value c based on a value of the load demand (e.g., theLDC index generated by the LDC 22) received at the input 102 a. In someembodiments, in addition to the LDC index, the control signal value cmay be determined based on a current value of a process variable used inthe power generating system received at the input 102 b and a value of asetpoint or desired value of the process variable received at the input102 c. As such, the model 110 may define a relationship between aparticular load demand, a particular current value of a processvariable, and the process variable setpoint. In some embodiments, themodel 110 may define a relationship between multiple load demand values,multiple possible current values of the process variables, and theprocess variable setpoint.

In some embodiments, in addition to the LDC index, the control signalvalue c may be determined based on a current value of a manipulatedvariable used in the power generating system received at the input 102d, a current value of a disturbance variable received at the input 102e, and/or a value of some other signal 102 f. Generally, the model 110may define one or more relationships between various values of loaddemand and various values of signals that may be received (either aloneor in combination) via the inputs 102 b-102 c of the dynamic matrixcontroller 100.

In an embodiment, the function D(i₁, i₂, . . . i_(n))=c that is executedby the dynamic matrix control routine 105 may be correspond to one ormore models 110 stored at the DMC 100. An example of the model 110 isshown in FIG. 3. FIG. 3 illustrates an example screen shot 200 displayedon a user interface of a power generating plant or system. The screenshot 200 includes an example model 202 that may be included in thedynamic matrix controller of FIG. 2. The model 202 may be an example ofan embodiment of the model 110 of FIG. 2, for instance, and the model202 may be included in an instance of a dynamic matrix controller 100used in conjunction with the turbine master 24.

The model 202 may be configured or generated based on parametric testingof the load or power generating system. In the example shown in FIG. 3,the model 202 is depicted as a two-dimensional plot of a processresponse 205 over time 208 showing the response of throttle pressure atthe turbine at a given initial system load when boiler output is changedduring parametric testing. To determine the model 202, parametrictesting was performed at the given initial system load. During testing,while the load generating system was operating in a steady-state at thegiven initial system load, a defined increase in the output of theboiler was demanded of the load generating system at the time 210. Thecurve 205 corresponds to the parametric data obtained during the testingprocess. In particular, the curve 205 corresponds to the response ofthrottle pressure of the turbine over time 208 that occurred due to therequested demand in boiler output at the initial time 210. As such, theplot 205 depicts the process response of the turbine for a definedsystem change at a known, initial steady-state load.

The parametric testing may be repeated to obtain data to determine,generate or configure one or more models 110 that are more accurate andcomplete. Generally, parametric testing may be performed forcombinations of various values of initial steady-state loads and variousvalues of types of system changes to determine various processresponses. For example, parametric testing may be performed fordifferent initial steady-state loads and/or for different changes inboiler output demands. Additionally or alternatively, parametric testingmay performed to gather parametric data for process responses other thanthrottle pressure. Still additionally or alternatively, parametrictesting may be performed for system changes other than boiler outputdemand.

Referring to the example shown in FIG. 3, data obtained from multipleparametric tests may be used to determine, configure and/or generate oneor more models 110 corresponding to the turbine, including the model202. The one or more models 110 may describe the behavior of differentprocess responses of the turbine at various loads and various systemchanges. The one or more models 110 may then be loaded into or otherwisemade available for use by an instance of the dynamic matrix controlroutine 105 in a DMC 100 of FIG. 2 that is used in conjunction with theturbine master 24.

In a similar manner, one or more parametric tests may be performed toobtain parametric data corresponding to various process responses of theboiler. The obtained parametric data may be used to determine, configureand/or generate one or more models 110 corresponding to the boiler. Theone or more models 110 may then be loaded into or otherwise madeavailable for use by an instance of the dynamic matrix control routine105 in a DMC 100 that is used in conjunction with the boiler master 26.

In FIG. 3, the embodiment of the model 202 depicts the model 110 as atwo-dimensional line graph 205. It is understood, however, that themodel 110 may be depicted in any desired form, such as a graph otherthan a two-dimensional plot, a mathematical model or formula, anarrangement of data, a pictorial representation, or other suitable form.In some embodiments, at least a portion of the model may be selected andmay be presented for viewing on a user interface. In some embodiments, asingle model 110 may be represented over multiple display views.

Furthermore, although the embodiment illustrated in FIG. 3 displays asingle model 110 representing response of throttle pressure that isincluded in the DMC 100, in other embodiments, more than one model 110may be included in the DMC 100. Each of the more than one models 110 maybe displayed, either by itself or in conjunction with other models. Forexample, each model may correspond to a different range of loadsgenerated by the power generating system or plant. In another example,each model may correspond to a different process response. One or moreappropriate models 110 may be selected for use in generating the controlsignal 108, in an embodiment.

Turning back to FIG. 2, the dynamic matrix control routine 105 thatdetermines the value of the control signal 108 may include a set ofcomputer executable instructions that are stored on a memory 112 of theDMC 100. The memory 112 may include one or more non-transitory,tangible, computer-readable media. For example, the memory 112 mayinclude one or more program memories for permanently storing datarelated to the computer executable instructions, and one or morerandom-access memories for temporarily storing data related to thecomputer executable instructions. The memory 112 may be implemented asone or more semiconductor memories, magnetically readable memories,optically readable memories, and/or other tangible, non-transitorycomputer-readable storage media, for example. The memory 112 may beaccessible to a processor 115 so that the processor 115 may execute theset of instructions on the memory corresponding to the dynamic matrixcontrol routine 105.

The model 110 may be stored on a same memory 112 as the dynamic matrixcontrol routine 105 or on a different memory (not shown) that is locallyor remotely accessible to the dynamic matrix control routine 105. Inconjunction with the execution of the dynamic matrix control routine105, the model 110 may be accessed by the dynamic matrix control routine105.

In an embodiment, the model 110 may be updated to reflect updated ordesired parametric data. For example, the model 110 may be automaticallymodified as plant data (e.g., process control data, measurements, etc.)changes in real-time, the model 110 may be automatically modified when athreshold is reached, the model 110 may be automatically modified atpredetermined time intervals, and/or the model 110 may be modified basedon a user command or instruction. An updated, modified model may bestored in the memory 112 so that subsequent, updated control signals 108are determined based on the modified model.

FIG. 4 illustrates a block diagram of an embodiment of the power grid 10of FIG. 1 where at least one of the plants 12, 14, and 16 may beswitched between model-based load demand control and PID control. InFIG. 4, only the plant 14 is shown as having the capability of beingswitched between model-based load demand control and PID control, butthe techniques illustrated and discussed for the plant 14 may beimplemented in the plant 12 and/or the plant 16. Further, although FIG.4 illustrates both the turbine master 24 and the boiler master 26 asincluding the capability of switching between model-based and PID basedcontrol, in some embodiments, only one of the turbine master 24 or theboiler master 26 may include the capability of switching betweenmodel-based and PID based control.

Still further, at least a portion of the techniques illustrated anddiscussed with respect to FIG. 4 may be used in conjunction with thedynamic matrix controller 100 of FIG. 2, with other model-basedcontrollers, or with other types of model-based control. For ease ofdiscussion and not for limiting purposes, though, the description ofFIG. 4 below includes references to the DMC 100 of FIG. 2.

FIG. 4 illustrates embodiments of the model-based turbine master 24 andthe model-based boiler master 26 that each support switching betweenmodel-based and PID based control respectively therein. With regard tothe turbine master 24 of FIG. 4, the turbine master 24 may include amodel-based control entity, apparatus or system 300 t, a PID controlentity, apparatus or system 302 t, and a switch 305 t that is configuredto activate one of the model-based control entity 300 t or the PIDcontrol entity 302 t. Similarly, the boiler master 26 of FIG. 4 mayinclude a model-based control entity, apparatus or system 300 b, a PIDcontrol entity, apparatus or system 302 b, and a switch 305 b configuredto activate one of the model-based control entity 300 b or the PIDcontrol entity 302 b. It is understood that the switches 305 t and 305 beach need not be mechanical switches, but may each be a programmableswitch, an electronically activated switch, or a switch that isactivated in any suitable manner.

In an embodiment, both model-based control entities 300 t, 300 b areactivated while both PID control entities 302 t, 302 b are deactivated.In an embodiment, only one of the model-based control entities 300 t,300 b is activated while the other is deactivated. In an example, tocontrollably move the power generating system from operating under PIDcontrol techniques 302 t, 302 b to model-based control techniques 300 t,300 b, a first switch (e.g., one of the switch 305 t and the switch 305b) may transfer its connection from PID control to model-based control,and then sequentially, the other switch may transfer its connection fromPID control to model-based control. In some embodiments, the activationand deactivation of the switches is based on user input. In someembodiments, the activation and deactivation of the switches isautomatically performed.

With regard to the model-based control entities, apparatuses or systems300 t and 300 b illustrated in FIG. 4, each of the model-based controlentities 300 t and 300 b may include a respective instance of the DMC100 that utilizes a respective set of one or more models 110. Forexample, the model-based control entity 300 t corresponding to theturbine master 24 may include a first instance of the DMC 100 thatreceives a first set of signals (e.g., via the input 102 a and one ormore of inputs 102 b-102 f), and that further includes a first set ofone or more respective models 110 that correspond to parametric testingof the turbine. In an embodiment, the model-based control entity 300 bcorresponding to the boiler master 26 may include a second instance ofthe DMC 100 that includes a second set of signals (e.g., via the input102 a and one or more inputs 102 b-102 f), and that further includes asecond set of one or more respective models 110 that correspond toparametric testing of the boiler. Typically, the first and the secondinstances of the DMC 100 may differ, and the first and the second setsof models and signals may also differ, but these differences are notrequired. Furthermore, the model-based control entity 300 t and themodel-based control entity 300 b are not each limited to being anembodiment of the DMC 100. Generally, any known model-based controlstrategy or entity may be included in the model-based control entity 300t and/or in the model-based control entity 300 b. In an embodiment, themodel-based control strategy used in the model-based control entity 300t may be different than that used in the model-based control entity 300b.

With regard to the PID control entities or paths 302 t and 302 b of FIG.4, an example PID control arrangement 310 corresponding thereto is shownin FIG. 5. In an embodiment, both of the PID control apparatuses,entities, paths, or routines 302 t and 302 b illustrated in FIG. 5 maybe activated in the PID control arrangement 310. In an embodiment, onlyone of the PID control apparatuses, entities, paths, or routines 302 tand 302 b is activated in the PID control arrangement 310. Of course,the PID control arrangement 310 shown in FIG. 5 is not the only PIDcontrol arrangement that may be used in conjunction with the turbinemaster 24 and the boiler master 26 of FIG. 4. Generally, any suitablePID control strategy or entity may be used for control of the turbinemaster 24, the boiler master 26, or both the turbine master 24 and theboiler master 26, and may be correspondingly activated by the switches305 t and 305 b.

In the embodiment illustrated in FIG. 5, the plant 14 may activate PIDcontrol for the turbine master 24, the boiler master 26, or both theturbine master 24 and the boiler master 26 (e.g., by configuring theswitches 305 t, 305 b accordingly). Upon activation of PID control, theLDC index produced by the LDC 22 may be used in the two separate controlpaths 302 t and 302 b, with the first control path 302 t beingresponsible for producing a control signal corresponding to the turbinemaster control unit 24 of FIG. 4 and the second control path 302 b beingresponsible for producing a boiler master control signal correspondingto the boiler master control unit 26 of FIG. 4. In some embodiments, PIDcontrol may be activated in both the turbine master 24 and in the boilermaster 26. In some embodiments, PID control may be activated in only oneof the turbine master 24 or the boiler master 26.

As shown in FIG. 5, in an embodiment, the LDC index may be provided toboth a feedforward controller 50 and a feedback controller 52 in theturbine control path 302 t which, in this case, are connected in aboiler follow mode although the well-known turbine follow mode ofcontrol could be used instead. In this case, the feedback controller 52may be indicated as being a PID controller although other types ofcontrollers could be used instead. Generally speaking, the feedbackcontroller 52 may compare the actual load currently being produced(e.g., in megawatts or in percentage of capacity) to the LDC index(which may also be in megawatts or percentage capacity) to produce anerror signal (not shown), in an embodiment. The PID controller 52 mayuse the error signal to produce a first turbine control signal which maybe provided to a signal combiner shown as a summer 54. The feedforwardcontroller 50 may operate on the LDC index and may produce a feedforward control signal which may be also provided to the summer 54. Thefeedback control signals (from the PID controller 52) and thefeedforward control signal (from the controller 50) may be combined inthe summer 54 to produce a turbine master control signal 56, in anembodiment. In one example, the summer 54 may operate to sum thefeedforward and feedback control signals and to scale the summed signalif necessary to produce an appropriate master control signal for theturbine system. The master control signal may be provided to the turbinevalves 28, to the bypass valves 30, and/or to additional entities withinthe plant 12.

In some embodiments of the PID control path 302 t (not shown), the feedforward controller 50 may be omitted so that the output of the PID 52 isequivalent to the turbine master control signal 56.

In a similar manner, the LDC index may be provided to a feed forwardcontroller 60 associated with the boiler control path 302 b, while afeedback controller 62 (illustrated as a PID controller) in the path 302b receives a pressure set point and an indication of the actual measuredpressure within the boiler, in an embodiment. The PID controller 62 maycompare, for example, the actual measured pressure in the boiler to thepressure set point, and may produce a feedback control signal using anyknown PID control technique. The feedback control signal may be providedto a signal combiner illustrated in FIG. 5 as a summer 64. Likewise, thefeed forward controller 60 may use the LDC index to produce afeedforward control signal which may be also provided to the summer 64,in an embodiment. The summer 64 may operate to combine the feedbackcontrol signal produced by the PID controller 62 with the feed forwardcontrol signal produced by the controller 60 to develop a boiler mastercontrol signal 66. Of course, in some embodiments, the summer 64 mayperform averaging, or weighted averaging of the two received controlsignals, and may perform scaling or some other combination procedure, toproduce the master boiler control signal 66. The master control signalmay be provided to adjust the fuel, air, and/or water flow 32 providedto the plant 12, for example.

In some embodiments of the PID control path 302 b (not shown), the feedforward controller 60 may be omitted, so that the output of the PID 62is equivalent to the boiler master control signal 66.

FIG. 6 illustrates an embodiment of a method 350 for controlling agenerated load of a power generating system. The method 350 may beimplemented, for example, in the power grid illustrated in FIGS. 1 and4, such as in one or more of the plants 12, 14, or 16, and the method350 may be used in conjunction with the dynamic matrix controller 100 ofFIG. 2, the PID control arrangement 302 t of FIG. 5, and/or the PIDcontrol arrangement 302 b of FIG. 5. For illustrative and not limitingpurposes, the method 350 is described with respect to FIGS. 1-5.

In an embodiment, the method 350 for controlling a load of a powergenerating system may include initiating a cessation or stopping of PIDcontrol 352 of a target entity or apparatus. For example, the targetapparatus may be a turbine in the power generating system. As such, thecessation of PID control utilized by the turbine master 24 may beinitiated 352 (e.g., by disconnecting the switch 305 t from the PIDcontrol apparatus or routine 302 t). In another example, the targetapparatus may be a boiler in the power generating system, and thus, thecessation of PID control utilized by the boiler master 26 may beinitiated 352 (e.g., by disconnecting the switch 305 b from the PIDcontrol apparatus or routine 302 b). Of course, other target apparatusesincluded in the load generating system other than a turbine or a boilermay be operated on (block 352). The cessation of PID control may beinitiated 352, for example, as a result of a manual command, or thecessation of PID control may be initiated 352 automatically.

At a block 355, model-based control of the target entity or apparatusmay be initiated. For example, if the target entity is a turbine, theturbine master 24 may start using model-based control 355 (e.g., byconnecting the switch 305 t to the model-based control apparatus orroutine 300 t), and if the target entity is a boiler, the boiler master26 may start using model-based control 355 (e.g., by connecting theswitch 305 b to the model-based control apparatus or routine 300 b). Ofcourse, other target apparatuses included in the load generating systemother than a turbine or a boiler may be operated on (block 355). In anembodiment, the model-based control 355 may include dynamic matrixcontrol, so that an instance of a DMC such as the DMC 100 is used toperform the model-based control that is initiated for the target entityor apparatus.

In an embodiment, the method 350 for controlling a load of a powergenerating system may include initiating a cessation or stopping of PIDcontrol 358 of a second target entity or apparatus. For example, if thefirst target apparatus for which PID control was initiated to be ceasedat the block 352 is a turbine, then the second target apparatus may be aboiler and PID control at the boiler master 26 may be initiated to beceased 358. If the first target apparatus for which PID control wasinitiated to be ceased at the block 352 is a boiler, then the secondtarget apparatus may be a turbine and PID control at the turbine master24 may be initiated to be ceased 358. Of course, other second targetapparatuses included in the load generating system other than a turbineor a boiler may be operated on (block 358). The cessation of PID controlmay be initiated 358, for example, as a result of a manual command, orthe cessation of PID control may be initiated 358 automatically.

At a block 360, model-based control of the second target entity orapparatus may be initiated. For example, if the second target entity isa turbine, the turbine master 24 may start using model-based control,and if the second target entity is a boiler, the boiler master 26 maystart using model-based control. Of course, other target apparatusesincluded in the load generating system other than a turbine or a boilermay be operated on (block 360). In an embodiment, the model-basedcontrol 352 may include dynamic matrix control, so that an instance of aDMC such as the DMC 100 is used to perform the model-based control.

In an embodiment, the first and the second target entities may besequentially activated to use model-based control (e.g., the block 355occurs before the block 360). The sequential activation may be based onuser input, the sequential activation may be automatically performed, orthe sequential activation may be performed based on a combination ofmanual and automatic instructions.

In an embodiment, the power generating system may be switched back toPID control, such as for testing purposes or in other situations. Atarget entity may be switched from model-based control to PID controlusing a respective switch. For example, the switch 305 t may be switchedfrom activating the model-based control 300 t to activate the PIDcontrol 302 t, or the switch 305 b may be switched from activating themodel-based control 300 b to activate the PID control 302 b. In someembodiments, a first target entity (e.g., the turbine or the boiler) maybe switched from model-based control to PID control before a secondtarget entity is switched from model-based control to PID control. Theswitching may be based on user input, the switching may be automaticallyperformed, or the switching may be performed based on a combination ofmanual and automatic instructions.

Referring simultaneously to FIG. 4, in an illustrative but non-limitingembodiment, a power generating system may include a turbine controlledby a turbine master 24 and a boiler controlled by a boiler master 26,both of which may be individually switched between PID control 302 t,302 b and model-based control 300 t, 300 b. In an initial state, boththe turbine master 24 and the boiler master 26 may utilize PID control302 t, 302 b to control the load generated by the power generatingsystem. For example, the switches 305 t and 305 b of FIG. 4 may beconfigured to activate PID control 302 t, 302 b so that the turbinemaster 24 and boiler master 26 may be controlled using a PID controlarrangement, such as the arrangement 310 illustrated in FIG. 5.

Cessation of PID control of a first target apparatus (e.g., either theturbine or the boiler, in this illustrative example) may be initiated(block 352), and model-based control may be started or activated (block358), for example, by configuring a corresponding switch 305 t or 305 bto activate the respective model-based control 300 t or 300 b.Accordingly, upon activation of the model-based control 300 t or 300 bof the first target apparatus, pressure within the power generatingsystem may change. To attain or maintain a desired load as indicated bythe load demand index generated by the LDC 22, however, the secondtarget apparatus may be controlled in a model-based manner (blocks 358,360) based on the model-based of control 300 t or 300 b of the firsttarget apparatus.

For example, when the first target apparatus or entity is the turbine,corresponding turbine and/or bypass valves 28, 30 may be controlled in amodel-based manner 300 t to be more open or more closed based on theload demand index 102 a. As a result, throttle pressure in the systemmay change. For example, if turbine valves are controlled to be moreclosed, pressure at or corresponding to the boiler may increase, and ifturbine valves are controlled to be more open, pressure at orcorresponding to the boiler may decrease. If the boiler is stilloperating under PID control 302 b, though, the response to the changedpressure may be markedly sluggish as compared to the quicker actingmodel-based control 300 t of the turbine. Accordingly, PID control 302 tof the boiler may be ceased or initiated to be ceased (block 358), andmodel-based control 300 b may be initiated for the boiler (block 360).In response to the changed pressure, the model-based control 300 b ofthe boiler 26 initiated at the block 360 may more efficiently andquickly control the boiler by controlling a fan 34, a mill 36, a pump38, a valve 40, and/or an amount of fuel, air or water 32 delivered tothe boiler to generate the desired load.

In a second example, when the first target apparatus or entity is theboiler, an amount of fuel 32 delivered to the boiler may be controlledin a model-based manner 300 b to change based on the load demand index102 a. As a result, pressure in the system may change. For example, ifadditional fuel is delivered to the boiler, pressure at or correspondingto the turbine may increase, and if the amount of fuel delivered to theboiler is decreased, pressure at or corresponding to the turbine maydecrease. If the turbine is still operating under PID control 302 t,though, the response to the changed pressure may be markedly sluggish ascompared to the quicker acting model-based control 300 b of the boiler.As such, PID control 302 t of the turbine may be ceased or initiated tobe ceased (block 358), and model-based control 300 t may be initiatedfor the turbine (block 360). In response to the changed pressure, themodel-based control 300 t of the turbine initiated at the block 360 maymore efficiently and quickly control the turbine by controlling one ormore turbine valves 28 and/or one or more bypass valves 30 to generatethe desired load.

In some embodiments of the method 350, the blocks 358 and 360 may beoptional. For instance, the method 350 may include switching only afirst portion the load or power generating system from PID control tomodel-based control (e.g., blocks 352, 355) and not a second portion(e.g., blocks 358, 36). Typically, but not necessarily, embodiments ofthe method 350 that omit the blocks 358 and 360 may occur when thesecond target apparatus or entity is not switchable between PID controland model-based control (for example, a target apparatus that does notsupport PID control at all), or during a testing situation.

In some embodiments of the method 350, the blocks 352 and 360 may beoptional. For example, some load or power generating systems, such asnon-legacy systems, may not utilize PID control for various entities,apparatuses or sections, and instead may utilize only model-basedcontrol for the various entities, apparatuses or sections. In thesesystems, a first entity, apparatus or section may be controlled usingfirst model-based control (block 355), and a second entity, apparatus orsection may be controlled using second model-based control (block 360)that is based on the first model-based control. For example, a turbinemaster 24 may include the first model-based control 300 t, and theboiler master 26 may include second model-based control 300 b whoserespective model(s) 110 are based at least partially on the firstmodel-based control 300 t. In another example, a boiler master 26 mayinclude first model-based control 300 b, and the turbine master 24 mayinclude second model-based control 300 t whose respective model(s) 110are based at least partially on the first model-based control 300 b. Inan embodiment, the one or more models 110 used by the second model-basedcontrol may be generated based on parametric testing of the system whilethe first model-based control is in operation.

FIG. 7 illustrates an embodiment of a method 380 for controlling a loadof a power generating system. The method 380 may be implemented, forexample, in the power grid illustrated in FIGS. 1 and 4, such as in oneor more of the plants 12, 14, or 16. The method 380 may be used inconjunction with the dynamic matrix controller 100 of FIG. 2 and/or withthe PID control arrangement 302 t of FIG. 5. The method 380 may be usedin conjunction with the method 350 of FIG. 6. For example, the method380 may be used in conjunction with the block 355 and/or the block 360of the method 350. In some embodiments, the method 380 may be used inconjunction with a method of controlling a load generated by a systemother than the method 350, or the method 380 may be a stand-alonemethod. For illustrative and not limiting purposes, the method 380 isdescribed with respect to FIGS. 1-5.

The method 380 may include receiving (block 382) a signal indicative ofa load demand at an input of a dynamic matrix controller. For example, asignal generated by the load demand controller 22 may be received 382 atthe input 102 a of the DMC 100. In some embodiments, one or moreadditional signals may be received at one or more other inputs of thedynamic matrix controller, such as a signal indicative of a currentvalue of a process variable 102 b, a signal indicative of a setpoint 102c of the process variable, a signal indicative of a current value of amanipulated variable 102 d, a signal indicative of a current value of adisturbance variable 102 e, and/or some other signal 102 f.

The dynamic matrix controller may determine (block 385) a value of acontrol signal based on the value of the load demand signal. In anembodiment, the dynamic matrix controller may determine the value of thecontrol signal by using a dynamic matrix control routine 105 and/or byusing one or more appropriate models 110, in a manner such as previouslydiscussed. In embodiments of the method 380 where one or more additionalsignals are received in addition to the load demand signal, the dynamicmatrix controller may determine the value of the control signal furtherbased on the one or more additional signals.

At block 388, the dynamic matrix controller may generate a controlsignal. For example, the dynamic matrix controller 100 may generate thecontrol signal 108.

At block 390, the dynamic matrix controller may control the loadgenerated by the power or load generating system based on the controlsignal. For example, the control signal 108 may be provided to controlone or more valves 28, 30, or 40, an amount of fuel, air, and/or waterdelivered to a boiler 32, one or more fans 34, one or more mills 36, oneor more pumps 38, and/or one or more other controlled entities orapparatuses that are included in the power or load generating system andthat influence the generated load.

An embodiment of the method 380 may be utilized by a power or loadgenerating system that includes at least two dynamic matrix controllers,where one of the at least two dynamic matrix controllers is configuredto control a first entity, apparatus or section of the power or loadgenerating system, and another one of the at least two dynamic matrixcontrollers is configured to control a second entity, apparatus orsection of the power or load generating system. For example, a firstdynamic matrix controller may control a turbine, and a second dynamicmatrix controller may control a boiler.

In this embodiment, a first instance of the method 380 may be executedwith respect to the first dynamic matrix controller, and a secondinstance of the method 380 may be executed with respect to the seconddynamic matrix controller. In particular, the first dynamic matrixcontroller may receive a signal indicative of a first process variablecorresponding to the first section of the power or load generatingsystem (block 382). The first dynamic matrix controller may determine(block 385) a value of a first control signal based on a signalindicative of the load demand, the signal indicative of a first processvariable, and any other additional received signals (e.g., setpoint ofprocess variable, current manipulated variable value, currentdisturbance variable value, etc.), and the first dynamic matrixcontroller may generate the first control signal (block 388).

A second dynamic matrix controller may receive the signal indicative ofthe load demand and a signal indicative of the first process variable ora second process variable corresponding to the second section of thepower or load generating system (block 382). The second dynamic matrixcontroller may determine (block 385) a value of a second control signalbased on signal indicative of the load demand, the signal indicative ofthe first process variable or the second process variable, and any otheradditional received signals (e.g., setpoint of process variable, currentmanipulated variable value, current disturbance variable value, etc.).The second dynamic matrix controller may generate a second controlsignal (block 388). The second control signal may be provided to thepower or load generating system (block 390) to control the loadgenerated by the system in conjunction with the first control signalgenerated by the first dynamic matrix controller (block 385).

FIG. 8 illustrates an embodiment of a method 400 for generating a modelfor use in model-based control of a power generating system. The method400 may be executed, for example, in conjunction with the power gridillustrated in FIGS. 1 and 4, such as in one or more of the plants 12,14, or 16. The method 400 may be executed in conjunction with thedynamic matrix controller 100 of FIG. 2. In an embodiment, the method400 may be used to generate the one or more models 110 of FIG. 2 or theexample model 202 illustrated in FIG. 3.

In some embodiments, the method 400 may be used in conjunction with themethod 350 and/or with the method 380 of FIG. 7. For example, the method400 may be pre-pended and/or appended to the method 350, and the method400 may be pre-pended and/or appended to the method 380. In someembodiments, the method 380 may be used in conjunction with a method ofcontrolling a load generated by a system other than the methods 350 and380. For illustrative and not limiting purposes, though, the method 380is described below with respect to FIGS. 1-5.

At block 402, parametric testing data may be obtained or received. Theparametric testing data may be generated or obtained using techniquessuch as previously described with respect to FIG. 3, and the parametricdata may be stored at a data storage device, such as in the memory 112,in a different local data storage area, or at a remote storage device(not shown). In an embodiment, the parametric testing data may beretrieved from or received from the data storage device.

At block 405, one or more models may be determined, configured, and/orgenerated based on the obtained parametric testing data. In anembodiment, a different model may be determined for different ranges ofinitial steady-state loads, for different levels or types of systemchanges, or for different process responses.

At block 408, the one or more determined or generated models may bestored so that the model(s) are locally or remotely accessible to thedynamic matrix controller 100 and/or to the dynamic matrix controlroutine 105. In an embodiment, the one or more models may be stored inthe memory 112. In an embodiment, a first portion of the one or moremodels may be stored locally (e.g., as the model 110), and a secondportion of the one or more models may be stored remotely at a networkeddata storage device (not shown).

The method 400 may include optional blocks 410-415. At block 410, thestored model(s) may be modified, updated or replaced. For example, atleast a portion of the one or more of the stored models may be modifiedor updated in real-time, or one or more of the models may beautomatically modified based on data obtained in real-time. In anotherexample, one or more of the stored models may be replaced or at leastpartially updated at a determined time interval. In other examples, oneor more of the stored model(s) may be replaced or at least partiallyupdated based on additional data when a threshold is reached, or when auser request to replace or update the model(s) is received. The modifiedmodel(s) may be stored so that the modified model(s) are locally orremotely accessible to the dynamic matrix controller 100 and/or to thedynamic matrix control routine 105.

At block 415, a subsequent, updated control signal may be generatedbased on the one or more modified models. For example, the dynamicmatrix controller 100 may generate a subsequent, updated control signal108 based on the modified model(s) and the load demand index 102 a tocontrol the load generated by the power generating system.

While the forgoing description of dynamic matrix control of a load hasbeen described in the context of controlling a power generating plantand, in particular, a boiler and turbine operated power generatingplant, these model-based control techniques can be used in other processcontrol systems, such as in industrial process control systems used tocontrol industrial or manufacturing processes. More particularly, thiscontrol method may be used in any process plant or control system thatreceives numerous set point changes and which controls slow reactingequipment. For example, model-based control techniques may be applied toammonia control for NO_(x) (nitric oxide and nitrogen dioxide)reduction, drum level control, furnace pressure control, and/or flue gasdesulphurization, to name a few.

Furthermore, although the forgoing text sets forth a detaileddescription of numerous different embodiments of the invention, itshould be understood that the scope of the invention may be defined bythe words of the claims set forth at the end of this patent and theirequivalents. The detailed description is to be construed as exemplaryonly and does not describe every possible embodiment of the inventionbecause describing every possible embodiment would be impractical, ifnot impossible. Numerous alternative embodiments could be implemented,using either current technology or technology developed after the filingdate of this patent, which would still fall within the scope of theclaims defining the invention. By way of example, and not limitation,the disclosure herein contemplates at least the following aspects:

1. A method of controlling a load generated by a power generatingsystem, including receiving a signal indicative of a load demand at aninput of a dynamic matrix controller; determining, by the dynamic matrixcontroller, a value of a control signal based on the signal indicativeof the load demand and a model stored in a memory of the dynamic matrixcontroller; generating, by the dynamic matrix controller, the controlsignal; and controlling the load generated by the power generatingsystem based on the control signal.

2. The method of the preceding aspect, further including receiving asignal indicative of a setpoint of a process variable used in the powergenerating system and a signal indicative of a current value of theprocess variable at additional inputs of the dynamic matrix controller;and

wherein determining the value of the control signal is further based onthe signal indicative of the setpoint of the process variable and thesignal indicative of the current value of the process variable.

3. The method of any of the preceding aspects, wherein the processvariable is a first process variable corresponding to a first section ofthe power generating system, the dynamic matrix controller is a firstdynamic matrix controller, the model is a first model, and the controlsignal is a first control signal; and

the method further includes receiving the signal indicative of the loaddemand, a signal indicative of a setpoint of a second process variablecorresponding to a second section of the power generating system, and asignal indicative of a current value of the second process variable atinputs of a second dynamic matrix controller;

determining, by the second dynamic matrix controller, a value of asecond control signal based on the signal indicative of the load demand,the signal indicative of the setpoint of the second process variable,the signal indicative of the current value of the second processvariable, and a second model stored in a memory of the second dynamicmatrix controller;

generating, by the second dynamic matrix controller, the second controlsignal; and controlling the load of the power generating system based onthe first control signal and on the second control signal.

4. The method of any of the preceding aspects, wherein the first sectionof the power generating system corresponds to one of a turbine or aboiler, and wherein the second section of the power generating systemcorresponds to the other one of the turbine or the boiler.

5. The method of any of the preceding aspects, wherein one of the firstprocess variable or the second process variable corresponds to athrottle pressure within the power generating system, and the other oneof the first process variable or the second process variable correspondsto an amount of fuel delivered to the power generating system.

6. The method of any of the preceding aspects, wherein determining thevalue of the control signal is further based on an additional signalthat is indicative of a current value of a disturbance variable and thatis received at a respective input of the dynamic matrix controller.

7. The method of any of the preceding aspects, wherein determining thevalue of the control signal based on the additional signal indicative ofthe current value of the disturbance variable includes determining thevalue of the control signal based on a signal indicative of at least oneof an amount of soot, a steam temperature, or an amount of burner tilt.

8. The method of any of the preceding aspects, further includingdetermining at least a portion of a configuration of the model based onparametric testing of at least a part of the power generating system,and storing the model in the memory of the dynamic matrix controller.

9. The method of any of the preceding aspects, further includingmodifying the model, storing the modified model in the memory of thedynamic matrix controller, generating a subsequent control signal basedon the modified model, and controlling the load of the power generatingsystem based on the subsequent control signal.

10. The method of any of the preceding aspects, wherein determining thevalue of the control signal based on the model stored in the memory ofthe dynamic matrix controller includes determining the value of thecontrol signal based on a model that is stored in the memory of thedynamic matrix controller and that defines a relationship between aprocess variable, a manipulated variable, and the load demand.

11. The method of controlling a load of a power generating system,including any of the preceding aspects, and including

generating, by a first dynamic matrix controller, a first control signalbased on a load demand and a first model stored in a memory of the firstdynamic matrix controller;

generating, by a second dynamic matrix controller, a second controlsignal based on the load demand and a second model stored in a memory ofthe second dynamic matrix controller; and

controlling the load of the power generating system based on the firstcontrol signal and on the second control signal.

12. The method of any of the preceding aspects, wherein controlling theload of the power generating system based on the first control signaland on the second control signal includes controlling one of a throttlepressure within the power generating system or an amount of fueldelivered to the power generating system based on the first controlsignal, and

controlling the other one of the throttle pressure within the powergenerating system or the amount of fuel delivered to the powergenerating system based on the second control signal.

13. The method of any of the preceding aspects, wherein generating thefirst control signal is further based on a first variable correspondingto a first section of the power generating system, and generating thesecond control signal is further based on a second variablecorresponding to a second section of the power generating system.

14. The method of any of the preceding aspects, wherein generating thefirst control signal based on the first variable corresponding to thefirst section of the power generating system includes generating thefirst control signal based on the first variable corresponding to one ofa turbine or a boiler of the power generating system; and

generating the second control signal based on the second variablecorresponding to the second section of the power generating systemincludes generating the second control signal based on the secondvariable corresponding to the other one of the turbine or the boiler ofthe power generating system.

15. The method of any of the preceding aspects, further includinginitiating a cessation of a PID (Proportional-Integral-Derivative)control routine within the power generating system, wherein the PIDcontrol routine is based on the first variable; and wherein generating,by the first dynamic matrix controller, the first control signal basedon the first variable occurs after the cessation of the PID controlroutine based on the first variable has been initiated.

16. The method of any of the preceding aspects, further includingreceiving a signal indicative of a current value of the first variableand a signal indicative of a desired value of the first variable at thefirst dynamic matrix controller, and receiving a signal indicative of acurrent value of the second variable and a signal indicative of adesired value of the second variable at the second dynamic matrixcontroller; and

wherein generating the first control signal further based on the firstvariable includes generating the first control signal based on thesignal indicative of the current value of the first variable and thesignal indicative of the desired value of the first variable inconjunction with the load demand and the first model, and

generating the second control signal further based on the secondvariable includes generating the second control signal based on thesignal indicative of the current value and the signal indicative of thedesired value of the second variable in conjunction with the load demandand the second model.

17. The method of any of the preceding aspects, wherein the firstvariable is a first process variable, the second variable is a secondprocess variable, and at least one of:

generating the first control signal is further based on a signalindicative of a current value of a first disturbance variable receivedat the first dynamic matrix controller;

generating the first control signal is further based on a signalindicative of a current value of a first manipulated variable receivedat the first dynamic matrix controller;

generating the second control signal is further based on a signalindicative of a current value of a second disturbance variable receivedat the second dynamic matrix controller; or

generating the second control signal is further based on a signalindicative of a current value of a second manipulated variable receivedat the second dynamic matrix controller.

18. The method of any of the preceding aspects, further including atleast one of:

modifying the first model, storing the modified first model in thememory of the first dynamic matrix controller, generating an updatedfirst control signal based on the modified first model, and controllingthe load of the power generating system based on the updated firstcontrol signal; or

modifying the second model, storing the modified second model in thememory of the second dynamic matrix controller, generating an updatedsecond control signal based on the modified second model, andcontrolling the load of the power generating system based on the updatedsecond control signal.

19. The method of any of the preceding aspects, further including atleast one of:

obtaining first parametric data corresponding to the power generatingsystem and generating the first model based on the first parametricdata; or obtaining second parametric data corresponding to the powergenerating system and generating the second model based on at least oneof the first parametric data or the second parametric data.

20. A power generating system, including a dynamic matrix controllerhaving an input to receive a signal indicative of a load demand for thepower generating system, a memory storing a model, a dynamic matrixcontrol routine configured to determine a value of a control signalbased on the model and a value of the load demand, and an output toprovide the control signal to control a load generated by the powergenerating system.

21. The power generating system of any of the preceding aspects, whereinthe input is a first input; the dynamic matrix controller furtherincludes a second input to receive a signal indicative of a currentvalue of a process variable used in the power generating system and athird input to receive a desired value of the process variable; and thedynamic matrix control routine is configured to determine the value ofthe control signal based on the model, the value of the load demand, thecurrent value of the process variable, and the desired value of theprocess variable.

22. The power generating system of any of the preceding aspects, whereinthe dynamic matrix control routine is configured to determine the valueof the control signal based on the model, the value of the load demand,the current value of the process variable, the desired value of theprocess variable, and a current value of a disturbance variable used inthe power generating system.

23. The power generating system of any of the preceding aspects, whereinthe current value of the disturbance variable corresponds to at leastone of: an amount of soot blowing, a steam temperature, or an amount ofburner tilt.

24. The power generating system of any of the preceding aspects, whereinthe dynamic matrix controller is a first dynamic matrix controller, theprocess variable is a first process variable, the dynamic matrix controlroutine is a first dynamic matrix control routine, and the controlsignal is a first control signal; and

wherein the power generating system further includes a second dynamicmatrix controller, the second dynamic matrix controller including afirst input to receive a signal indicative of a current value of asecond process variable used in the power generating system, a secondinput to receive a signal indicative of a desired value of the secondprocess variable, a third input to receive the signal indicative of theload demand, a memory storing a second model, a second dynamic matrixcontrol routine configured to determine a value of a second controlsignal based on the second model, the value of the load demand, thecurrent value of the second process variable, and the desired value ofthe second process variable, and an output to provide the second controlsignal to control the load of the power generating system in conjunctionwith the first control signal.

25. The power generating system of any of the preceding aspects, whereinthe first dynamic matrix controller and the second dynamic matrixcontroller are sequentially activated.

26. The power generating system of any of the preceding aspects, whereina sequential activation of the first dynamic matrix controller and thesecond dynamic matrix controller is based on user input.

27. The power generating system of any of the preceding aspects, furtherincluding a turbine and a boiler in fluid connection with the turbine;and wherein the control signal is provided by the output of the dynamicmatrix controller to control one of a throttle pressure of the turbineor an amount of fuel delivered to the boiler.

28. The power generating system of any of the preceding aspects, whereinthe control signal is provided by the output of the dynamic matrixcontroller to control at least one of a valve, a fan, a mill, or a pumpcorresponding to the one of the throttle pressure of the turbine or theamount of fuel delivered to the boiler.

29. The power generating system of any of the preceding aspects, furtherincluding a switch for indicating the one of the throttle pressure ofthe turbine or the amount of fuel delivered to the boiler is to becontrolled by the control signal provided by the output of the dynamicmatrix controller, or for indicating the one of the throttle pressure ofthe turbine or the amount of fuel delivered to the boiler is to becontrolled by a control signal provided by aProportional-Integral-Derivative (PID) control entity.

30. The power generating system of any of the preceding aspects, whereinthe dynamic matrix controller is a first dynamic matrix controller, themodel is a first model, and the control signal is a first controlsignal; and

the power generating system further includes a second dynamic matrixcontroller having an output providing a second control signal to controlthe other one of the throttle pressure of the turbine or the amount offuel delivered to the boiler, the second control signal being based on asecond model stored in a memory of the second dynamic matrix controller.

31. The power generating system of any of the preceding aspects, whereinthe model stored in the memory of the dynamic matrix controller isconfigured based on parametric testing.

32. The power generating system of any of the preceding aspects, whereinthe model stored in the memory of the dynamic matrix controller ismodifiable in real-time.

Thus, many modifications and variations may be made in the techniquesand structures described and illustrated herein without departing fromthe spirit and scope of the present invention. Accordingly, it should beunderstood that the methods and apparatus described herein areillustrative only and are not limiting upon the scope of the invention.

What is claimed is:
 1. A method of controlling a load generated by apower generating system, comprising: receiving a signal indicative of aload demand at an input of a dynamic matrix controller; determining, bythe dynamic matrix controller, a value of a control signal based on thesignal indicative of the load demand and a model stored in a memory ofthe dynamic matrix controller; generating, by the dynamic matrixcontroller, the control signal; and controlling the load generated bythe power generating system based on the control signal.
 2. The methodof claim 1: further comprising receiving a signal indicative of asetpoint of a process variable used in the power generating system and asignal indicative of a current value of the process variable atadditional inputs of the dynamic matrix controller; and whereindetermining the value of the control signal is further based on thesignal indicative of the setpoint of the process variable and the signalindicative of the current value of the process variable.
 3. The methodof claim 2, wherein: the process variable is a first process variablecorresponding to a first section of the power generating system, thedynamic matrix controller is a first dynamic matrix controller, themodel is a first model, and the control signal is a first controlsignal; and the method further comprises: receiving the signalindicative of the load demand, a signal indicative of a setpoint of asecond process variable corresponding to a second section of the powergenerating system, and a signal indicative of a current value of thesecond process variable at inputs of a second dynamic matrix controller;determining, by the second dynamic matrix controller, a value of asecond control signal based on the signal indicative of the load demand,the signal indicative of the setpoint of the second process variable,the signal indicative of the current value of the second processvariable, and a second model stored in a memory of the second dynamicmatrix controller; and generating, by the second dynamic matrixcontroller, the second control signal; and controlling the load of thepower generating system based on the first control signal and on thesecond control signal.
 4. The method of claim 3, wherein the firstsection of the power generating system corresponds to one of a turbineor a boiler, and wherein the second section of the power generatingsystem corresponds to the other one of the turbine or the boiler.
 5. Themethod of claim 3, wherein one of the first process variable or thesecond process variable corresponds to a throttle pressure within thepower generating system, and the other one of the first process variableor the second process variable corresponds to an amount of fueldelivered to the power generating system.
 6. The method of claim 2,wherein determining the value of the control signal is further based onan additional signal that is indicative of a current value of adisturbance variable and that is received at a respective input of thedynamic matrix controller.
 7. The method of claim 6, wherein determiningthe value of the control signal based on the additional signalindicative of the current value of the disturbance variable comprisesdetermining the value of the control signal based on a signal indicativeof at least one of: an amount of soot, a steam temperature, or an amountof burner tilt.
 8. The method of claim 1, further comprising:determining at least a portion of a configuration of the model based onparametric testing of at least a part of the power generating system;and storing the model in the memory of the dynamic matrix controller. 9.The method of claim 1, further comprising modifying the model, storingthe modified model in the memory of the dynamic matrix controller,generating a subsequent control signal based on the modified model, andcontrolling the load of the power generating system based on thesubsequent control signal.
 10. The method of claim 1, whereindetermining the value of the control signal based on the model stored inthe memory of the dynamic matrix controller comprises determining thevalue of the control signal based on a model that is stored in thememory of the dynamic matrix controller and that defines a relationshipbetween a process variable, a manipulated variable, and the load demand.11. A method of controlling a load of a power generating system,comprising: generating, by a first dynamic matrix controller, a firstcontrol signal based on a load demand and a first model stored in amemory of the first dynamic matrix controller; generating, by a seconddynamic matrix controller, a second control signal based on the loaddemand and a second model stored in a memory of the second dynamicmatrix controller; and controlling the load of the power generatingsystem based on the first control signal and on the second controlsignal.
 12. The method of claim 11, wherein controlling the load of thepower generating system based on the first control signal and on thesecond control signal comprises: controlling one of a throttle pressurewithin the power generating system or an amount of fuel delivered to thepower generating system based on the first control signal, andcontrolling the other one of the throttle pressure within the powergenerating system or the amount of fuel delivered to the powergenerating system based on the second control signal.
 13. The method ofclaim 11, wherein: generating the first control signal is further basedon a first variable corresponding to a first section of the powergenerating system; and generating the second control signal is furtherbased on a second variable corresponding to a second section of thepower generating system.
 14. The method of claim 13, wherein: generatingthe first control signal based on the first variable corresponding tothe first section of the power generating system comprises generatingthe first control signal based on the first variable corresponding toone of a turbine or a boiler of the power generating system; andgenerating the second control signal based on the second variablecorresponding to the second section of the power generating systemcomprises generating the second control signal based on the secondvariable corresponding to the other one of the turbine or the boiler ofthe power generating system.
 15. The method of claim 13, furthercomprising initiating a cessation of a PID(Proportional-Integral-Derivative) control routine within the powergenerating system, wherein the PID control routine is based on the firstvariable; and wherein generating, by the first dynamic matrixcontroller, the first control signal based on the first variable occursafter the cessation of the PID control routine based on the firstvariable has been initiated.
 16. The method of claim 13, furthercomprising: receiving a signal indicative of a current value of thefirst variable and a signal indicative of a desired value of the firstvariable at the first dynamic matrix controller, and receiving a signalindicative of a current value of the second variable and a signalindicative of a desired value of the second variable at the seconddynamic matrix controller; and wherein: generating the first controlsignal further based on the first variable comprises generating thefirst control signal based on the signal indicative of the current valueof the first variable and the signal indicative of the desired value ofthe first variable in conjunction with the load demand and the firstmodel, and generating the second control signal further based on thesecond variable comprises generating the second control signal based onthe signal indicative of the current value and the signal indicative ofthe desired value of the second variable in conjunction with the loaddemand and the second model.
 17. The method of claim 16, wherein thefirst variable is a first process variable, the second variable is asecond process variable, and at least one of: generating the firstcontrol signal is further based on a signal indicative of a currentvalue of a first disturbance variable received at the first dynamicmatrix controller; generating the first control signal is further basedon a signal indicative of a current value of a first manipulatedvariable received at the first dynamic matrix controller; generating thesecond control signal is further based on a signal indicative of acurrent value of a second disturbance variable received at the seconddynamic matrix controller; or generating the second control signal isfurther based on a signal indicative of a current value of a secondmanipulated variable received at the second dynamic matrix controller.18. The method of claim 11, further comprising at least one of:modifying the first model, storing the modified first model in thememory of the first dynamic matrix controller, generating an updatedfirst control signal based on the modified first model, and controllingthe load of the power generating system based on the updated firstcontrol signal; or modifying the second model, storing the modifiedsecond model in the memory of the second dynamic matrix controller,generating an updated second control signal based on the modified secondmodel, and controlling the load of the power generating system based onthe updated second control signal.
 19. The method of claim 11, furthercomprising at least one of: obtaining first parametric datacorresponding to the power generating system and generating the firstmodel based on the first parametric data; or obtaining second parametricdata corresponding to the power generating system and generating thesecond model based on at least one of the first parametric data or thesecond parametric data.
 20. A power generating system, comprising: adynamic matrix controller including: an input to receive a signalindicative of a load demand for the power generating system, a memorystoring a model, a dynamic matrix control routine configured todetermine a value of a control signal based on the model and a value ofthe load demand, and an output to provide the control signal to controla load generated by the power generating system.
 21. The powergenerating system of claim 20, wherein: the input is a first input; thedynamic matrix controller further includes a second input to receive asignal indicative of a current value of a process variable used in thepower generating system and a third input to receive a desired value ofthe process variable; and the dynamic matrix control routine isconfigured to determine the value of the control signal based on themodel, the value of the load demand, the current value of the processvariable, and the desired value of the process variable.
 22. The powergenerating system of claim 21, wherein the dynamic matrix controlroutine is configured to determine the value of the control signal basedon the model, the value of the load demand, the current value of theprocess variable, the desired value of the process variable, and acurrent value of a disturbance variable used in the power generatingsystem.
 23. The power generating system of claim 22, wherein the currentvalue of the disturbance variable corresponds to at least one of: anamount of soot blowing, a steam temperature, or an amount of burnertilt.
 24. The power generating system of claim 21, wherein the dynamicmatrix controller is a first dynamic matrix controller, the processvariable is a first process variable, the dynamic matrix control routineis a first dynamic matrix control routine, and the control signal is afirst control signal; and wherein the power generating system furthercomprises a second dynamic matrix controller, the second dynamic matrixcontroller including: a first input to receive a signal indicative of acurrent value of a second process variable used in the power generatingsystem, a second input to receive a signal indicative of a desired valueof the second process variable, a third input to receive the signalindicative of the load demand, a memory storing a second model, a seconddynamic matrix control routine configured to determine a value of asecond control signal based on the second model, the value of the loaddemand, the current value of the second process variable, and thedesired value of the second process variable, and an output to providethe second control signal to control the load of the power generatingsystem in conjunction with the first control signal.
 25. The powergenerating system of claim 24, wherein the first dynamic matrixcontroller and the second dynamic matrix controller are sequentiallyactivated.
 26. The power generating system of claim 25, wherein asequential activation of the first dynamic matrix controller and thesecond dynamic matrix controller is based on user input.
 27. The powergenerating system of claim 20, further comprising a turbine and a boilerin fluid connection with the turbine; and wherein the control signal isprovided by the output of the dynamic matrix controller to control oneof a throttle pressure of the turbine or an amount of fuel delivered tothe boiler.
 28. The power generating system of claim 27, wherein thecontrol signal is provided by the output of the dynamic matrixcontroller to control at least one of a valve, a fan, a mill, or a pumpcorresponding to the one of the throttle pressure of the turbine or theamount of fuel delivered to the boiler.
 29. The power generating systemof claim 27, further comprising a switch for indicating: the one of thethrottle pressure of the turbine or the amount of fuel delivered to theboiler is to be controlled by the control signal provided by the outputof the dynamic matrix controller, or the one of the throttle pressure ofthe turbine or the amount of fuel delivered to the boiler is to becontrolled by a control signal provided by aProportional-Integral-Derivative (PID) control entity.
 30. The powergenerating system of claim 27, wherein: the dynamic matrix controller isa first dynamic matrix controller, the model is a first model, and thecontrol signal is a first control signal; and the power generatingsystem further comprises a second dynamic matrix controller having anoutput providing a second control signal to control the other one of thethrottle pressure of the turbine or the amount of fuel delivered to theboiler, the second control signal being based on a second model storedin a memory of the second dynamic matrix controller.
 31. The powergenerating system of claim 20, wherein the model stored in the memory ofthe dynamic matrix controller is configured based on parametric testing.32. The power generating system of claim 20, wherein the model stored inthe memory of the dynamic matrix controller is modifiable in real-time.